Courtesy : www.emerson.com

Energy management white paper

Your process plant is unique, but every plant can see the impact of high and rising energy costs. Yet,
pinpointing where energy is being consumed, and where it could be saved, remains a challenge for
many energy managers. Energy use within industrial facilities is very complex. There are thousands
of manufacturing processes in operation and no two are exactly the same, even within the same
organization. However, the opportunities for saving energy are significant, and the financial and
environmental payoffs make just about any improvements worthwhile. So, the question is, where do
you start?
In this report we identify five key measurement priorities that should be a concern for any plant
management team who is looking to reduce energy use. For each of these areas, Emerson has some
unique measurement and monitoring capabilities that will allow you to better manage energy use
throughout your plant.
We believe some top measurement priorities you should consider are:


Most industrial plants use steam heat to provide the energy that drives processes. The obvious
components of this steam system are the boilers and steam distribution lines. A critical
component of the steam system that is often overlooked is the steam traps; the mechanical
valves that let condensed water out of your system, while keeping the steam in. A large plant
can have thousands of steam traps distributed across the steam system.
When a steam trap fails, it occurs in one of two ways: open or closed. An open steam trap will
leak steam, wasting valuable energy. A closed steam trap will allow condensed water to build up
in the steam pipe, causing reliability issues and “water hammer” events that can damage the
steam system and any connected plant equipment. Steam traps have an average expected life
of about 5 years, so regular replacement of failed traps is essential to proper operation of your
steam system.
Failed steam traps are not always obvious. They are usually detected during manual inspection
rounds which are often scheduled on an annual, or even less frequent, basis. A typical plant’s
energy bill can be $20 million to $30 million per year and, according to the U.S. Department of
Energy(1), “In steam systems that have not been maintained for 3 to 5 years, between 15% and
30% of the installed steam traps may have failed – thus allowing live steam to escape.”
The Rosemount® 708 Wireless Acoustic Transmitter, operating on an Emerson Smart Wireless
network, monitors steam traps continuously and identifies failed traps immediately. The device
itself is very easy to install – and it’s non-intrusive. You simply attach it to the pipe upstream
from the steam trap with the supplied stainless steel mounting bands. It’s a very small,
lightweight device that can be readily put in tight spots and hazardous areas. We recommend
you monitor your critical traps – those that have high potential for steam loss if failed open – or
those that play a critical role in your process. The Rosemount 708 Transmitters will self-organize
into a network that will give you real-time information about the health of your steam system.
At Barking Power in the UK, 35 acoustic transmitters were installed on steam traps. In the first
week of operation, this new technology identified a leak from a high-pressure superheater
steam trap. The cost of that leak was estimated to be over €1400 ($2,200) for every 24 hours of
operation. “These devices give us a better picture of what is happening,” said Tony Turp, Senior
Control Engineer. He also noted that Barking Power can now better use their maintenance
resources by planning repairs in advance. “Overall, we have improved plant efficiency, reduced
steam losses, and improved the safety and productivity of our people,” He said.
South African petrochemical company, Sasol Technology, installed acoustic transmitters on 20
critical steam traps for an estimated $42,000 annual savings in steam costs. And, because
manual inspections on those traps are now reduced to a few manual inspections per year, Sasol
realized a savings of $15,627 in annual maintenance costs. “With on-line acoustic monitoring,
the facility now gets an early warning when steam traps fail,” said Dr. André Joubert, Control
Systems and Instrumentation Manager. “Overall, the smart acoustic transmitters paid for
themselves in under 3 months,” he concluded.

Utility fluids are the life blood of your plant. Water, air, gas and steam are all crucial to your
operations; while a shortage of any one of these could cause your plant to shut down.
Customers often tell us: “Sure, I can tell you how much natural gas we buy in a year, but I have no
idea how much is used by each process unit.” Every plant is different, but it is reasonable to say
for most plants, that 5 to 15% of a site’s energy is wasted in the form of lost or misused utility
fluids. This could be an opportunity to save between $1 million to $15 million per year.
It is commonly said that “You can’t manage what you don’t measure.” You need flowmetering of
all utility fluids in your plant so that you can understand the usage patterns throughout your
plant. With this information, you can balance flows of energy to key use points, detect leaks or
other unusual changes in consumption, prioritize energy-saving actions, and communicate key
performance indicators (KPI’s) for energy so that plant personnel understand how they can best
improve performance.
Emerson makes many different flowmeters, each appropriate for different fluids, enabling the
best performance and accuracy for your various utility fluid flow measurement applications. For
example, so-called “integrated differential pressure (DP) flowmeters” have much lower installed
cost compared than conventional orifice meters. Another technology available to reduce
installation costs for your system is wireless. Rosemount Smart Wireless instruments can be
installed for as little as a quarter of the cost of wired instruments.
We recommend that you measure flow of each key utility fluid at all energy account centers, the
key consumers of energy or major sub-sections of the plant. These meters provide information
to an Energy Management Information System (EMIS), which interprets and analyzes the
information to alert you to changes representing wasted energy. The Emerson Energy Advisor™
EMIS software is a simple bolt-on to the world’s leading historian software, OSI PI. With this
software, you have a comprehensive information system that gives you visibility and energy
decision-making capability for the life of your plant. In short, Rosemount flowmetering, along
with EMIS software, gives you a chance to get back that 15% of wasted energy in your utility
fluids systems.
To help offset the costs of rising fuel prices, a pulp and paper mill in New England implemented a
comprehensive energy management program. “We quickly realized that to save energy, we
needed to measure it,” said the mill’s energy manager. “We knew our total energy usage, but
had never measured individual energy areas.” After considering many different flow
measurement technologies, the mill installed two wireless networks, each with a Smart
Wireless Gateway that integrates seamlessly into their DeltaV control system. A total of 60
Rosemount Wireless 3051SFA Annubar® Flowmeters were installed on lines carrying steam, air,
warm water, fresh water and condensate. “We can now account for nearly all energy use within
the mill,” said the project engineer. “The wireless information has enabled us to focus our
attention on high energy areas first, and those which have the biggest impact on our cost
position.” The result for this mill is that the project paid for itself in less than eight months, with
savings well over $1 million in energy costs the first year.

The compressed air system in your plant is a major energy user. Compressed air systems
generally have many leaks and other sources of waste. Measuring flow in a compressed air
system helps identify leaks and manage air use. Measurement of air use is best done with several
points of flow measurement throughout the compressed air system. Flow measurements can be
made at each compressor, at the header, and at each major branch line. More points of flow
measurement allow tighter control of leaks and better management of the compressed air
system health.
Measuring flow can be done in various ways, and each type of flow measurement will cause a
permanent pressure loss (PPL) for each measurement point. The most common form of flow
measurement is an orifice plate flowmeter. Unfortunately, the orifice plate creates a large
permanent pressure loss in the compressed air system. Each of the permanent pressure losses
add up, and result in a large waste of energy drawn by the compressors. This is why it is critical to
consider to the permanent pressure loss of any new flowmeter that may be installed into a
compressed air system.
The Rosemount Annubar Flowmeter creates much less permanent pressure loss than other
measurements, averaging only 5% of the permanent pressure loss of an orifice plate flowmeter.
This reduced level of permanent pressure loss is negligible in the calculation of energy
consumed in the compressed air system.
In one documented case, a South American chemical plant achieved a dramatic increase in
compressed air system efficiency, and reduced electricity costs. In this case, usage of
compressed air was rising rapidly, increasing operational costs and driving a need for increased
capacity. This plant was also concerned with the risk of compressed air shortages, which could
lead to failure of pneumatic equipment. Engineers found that orifice plate flowmeters were
creating high permanent pressure loss in the compressed air system. Their solution involved the
removal of the orifice plate flowmeters, and installation of ten Rosemount Annubar Flowmeters;
nine to monitor the output of each of the nine compressors and one to measure flow on the
main header. These ten points of flow measurement allow the operators to identify increased
usage early without unnecessary system pressure loss, which was greatly reduced when the
orifice plates were replaced by low-pressure-loss Annubar flowmeters. The result of this was an
increase in overall compressed air system efficiency of 10%, and a reduction in electricity costs
of $750,000 per year. An added benefit was improved line pressure at remote locations in their
system.

In boilers, the water level in the steam drum must be precisely controlled to optimize steam
production, maximize boiler efficiency and maintain safe operation. If water level is too low,
there is a risk of damaging the boiler and significant risk of costly boiler trips. If water level is too
high, water could be carried with the steam, which reduces heat transfer effectiveness and can
cause damage to the downstream turbine. The most efficient performance of your steam
system is when the boilers are operating stably, and costly cycles of shut-down, purge and
re-start are avoided. Reliable drum level measurements are a very important part of achieving
that desired operating condition.


Traditionally, steam boiler water level has been measured by multiple methods, including simple
mechanical mechanisms, and various electronic gauging systems. The boiler and pressure
vessel code (BPVC) requires a local, visual indication of drum water level. This is provided by the
use of sight glasses, magnetic level indicators or systems such as the Emerson Hydrastep
electronic gauging system. The BPVC also requires additional, redundant level measurement of
the liquid in the boiler drum. These are often more advanced, electronic systems used to control
the boiler water level.
More advanced systems for boiler drum level control employ differential pressure (DP) level
measurements. However, a DP level measurement must be corrected based on temperature
and pressure conditions in the boiler, which will cause changes in the density of the liquid being
measured. This density compensation is especially important during the transient conditions of
changing steam demand and during start-up or shut-down.
Guided Wave Radar (GWR) transmitters provide an alternative for steam drum level
measurement, as they offer a number of important advantages over DP level technology. GWR
transmitters measure level in a way that is completely independent of liquid density, so the
complexity of density compensation is not required. Further, GWR transmitters are able to
measure level at temperatures up to 400°C and pressures up to 345 bar. They provide accurate
and reliable measurements of liquid level even when the operating environment includes
mechanical vibration and high turbulence. Finally, GWR transmitters have no moving parts,
providing low maintenance and high reliability.
In a typical installation, the GWR transmitter is mounted on top of a chamber that is external to
the boiler, with a probe extending from the GWR to the full depth of the chamber. A low energy
microwave pulse is sent down the probe, and when it reaches the liquid surface, a reflection is
sent back up to the transmitter. The transmitter measures the time taken for the pulse to reach
the liquid surface and be reflected back, and an on-board microprocessor calculates the liquid
level. In this way, the boiler drum level is measured directly, with no liquid density correction
required.
To meet the BPVC requirements for local indication and redundancy in boiler drum level
applications, we recommend a combination of a magnetic level gauge and a Guided Wave Radar
transmitter installed in an adjacent chamber. When redundant drum level measurements are
required or desired, a DP level measurement can be used in addition to the guided wave radar.
Together these devices provide a low-maintenance solution that provides easy-to-read local
indication for operators and a high degree of accuracy for control of boiler drum level.
A major paper mill in the United States was experiencing lost production and increased utility
costs due to boiler trips during routine start-ups. Boiler trips were caused by an error in the
boiler level reading of a DP transmitter installed with impulse lines. The DP level transmitter is
calibrated for full boiler operating pressure and temperature. However, during start-up when
the boiler was cold, water and steam density differences in the impulse lines were causing an
error in the DP level reading. The solution was to supplement the DP measurement with a
Rosemount 5301 Guided Wave Radar with Dynamic vapor Compensation. With more accurate
level readings during all process conditions from start-up to full output, boiler trips during
start-up are minimized. This paper mill now enjoys increased boiler efficiency, minimized
unplanned process shutdowns and increased production.